This invention relates to the drilling, completion, and stimulation of hydrocarbon wells and in particular to fluids and methods for gravel packing, cleanup or drilling in a subterranean formation.
Viscous fluids play many important roles in oilfield service applications. The viscosity of the fluids allows them to carry particles from one region of the formation, the wellbore, or the surface equipment to another. For instance, one of the functions of a drilling fluid is to carry drilling cuttings from around the drilling bit out of the wellbore to the surface. Fluid viscosity also plays an essential role for instance in gravel packing placement. Gravel packing essentially consists of placing a gravel pack around the perimeter of a wellbore across the production zone to minimize sand production from highly permeable formations.
Solid suspension properties are also an important requirement for fracturing fluids. For a well to produce hydrocarbons from a subterranean geologic formation, the hydrocarbons have to follow a sufficiently unimpeded flow path from the reservoir to the wellbore. If the formation has relatively low permeability, either naturally or through formation damages resulting for example from addition of treatment fluids or the formation of scales, it can be fractured to increase the permeability. Fracturing involves literally breaking a portion of the surrounding strata, by injecting a fluid directed at the face of the geologic formation, at pressures sufficient to initiate and/or extend a fracture in the formation. A fracturing fluid typically comprises a proppant, such as ceramic beads or sand to hold the fracture open after the pressure is released. It is therefore important for the fluid to be viscous enough to carry the proppant into the fracture.
The fluid viscosity is most commonly obtained by adding water-soluble polymers, such as polysaccharide derivatives. Recently, viscoelastic surfactants have been used as thickeners. Unlike the polymers, viscoelastic surfactants based fluids do not lead to reduction of permeability due to solid deposits, and exhibit lower friction pressure. In addition, the viscosity of the fluid is reduced or lost upon exposure to formation fluids such as for instance crude oil thereby ensuring better fracture clean-up.
Viscoelastic surfactant fluids are normally made by mixing in appropriate amounts suitable surfactants such as anionic, cationic, nonionic and zwitterionic surfactants. The viscosity of viscoelastic surfactant fluids is attributed to the three dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate into species such as micelles, which can interact to form a network exhibiting elastic behavior. In the remaining part of this description, the term xe2x80x9cmicellexe2x80x9d will be used as a generic term for the organized interacting species.
Cationic viscoelastic surfactantsxe2x80x94typically consisting of long-chain quaternary ammonium salts such as cetyltrimethylammonium bromide (CTAB)xe2x80x94have been so far of primarily commercial interest in wellbore fluid. Common reagents that generate viscoelasticity in the surfactant solutions are salts such as ammonium chloride, potassium chloride, sodium salicylate and sodium isocyanate and non-ionic organic molecules such as chloroform. The electrolyte content of surfactant solutions is also an important control on their viscoelastic behavior. Reference is made for example to U.S. Pat. Nos. 4,695,389, No. 4,725,372, No. 5,551,516, No. 5,964,295, and No. 5,979,557. However, fluids comprising this type of cationic viscoelastic surfactants usually tend to lose viscosity at high brine concentration (10 pounds per gallon or more). Therefore, these fluids have seen limited use as gravel-packing fluids or drilling fluids, or in other applications requiring heavy fluids to balance well pressure.
It is also known from International Patent Publication WO 98/56497, to impart viscoelastic properties using amphoteric/zwitterionic surfactants and an organic acid, salt and/or inorganic salt. The surfactants are for instance dihydroxyl alkyl glycinate, alkyl ampho acetate or propionate, alkyl betaine, alkyl amidopropyl betaine and alkylamino mono- or di-propionates derived from certain waxes, fats and oils. The surfactants are used in conjunction with an inorganic water-soluble salt or organic additives such as phthalic acid, salicylic acid or their salts. Amphoteric/zwitterionic surfactants, in particular those comprising a betaine moiety are useful at temperature up to about 150xc2x0 C. and are therefore of particular interest for medium to high temperature wells. However, like the cationic viscoelastic surfactants mentioned above, they are not compatible with high brine concentration.
This invention provides a viscoelastic fluid, useful as a thickener for the suspension of particles, in particular useful as thickener for wellbore fluids, which retain viscosity at high brine concentrations.
According to a first embodiment, this invention specifically relates to a fluid comprising a high brine carrier fluid having a density of at least 10 ppg (10 pounds per gallon or 1.198 g/cm3], a member selected from the group consisting of organic acids, organic acid salts, inorganic salts and combination of one or more organic acids or organic acid salts, an amount of a zwitterionic surfactant represented by the formula: 
wherein R1 is an alkyl, alkylarylakyl, alkoxyalkyl, alkylaminoalkyl or alkylamidoalkyl group, containing from about 12 to about 24 carbon atoms, branched or straight chains, saturated or unsaturated, and R2 and R3 are independently hydrogen or an aliphatic chain having from 1 to about 30 carbon atoms, and R4 is a hydrocarbyl radical having from 1 to 4 carbon atoms and a co-surfactant.
The co-surfactant increases the gel strength of the viscoelastic-based fluid, if desired. A preferred co-surfactant is a salt of an alkyl benzene sulfonate, most preferred salts being sodium dodecylbenzenesulfonate (SDBS) and sodium dodecylsulfate (SDS). Alkyl phosphonates and alkylcarboxylates may also be used. The concentration of the co-surfactant in the fluid is preferably about 0.1 wt % to about 1 wt %. More preferably, the concentration of the co-surfactant in the fluid is about 0.29 wt % to about 0.5 wt %. The compositions of the invention are also compatible with mineral and organic acids.
According to a second embodiment, this invention specifically relates to a fluid comprising a high brine carrier fluid having a density of at least 10 ppg (10 pounds per gallon or 1.198 g/cm3), a member selected from the group consisting of organic acids, organic acid salts, inorganic salts and combination of one or more organic acids or organic acid salts, an amount of a zwitterionic surfactant represented by the formula: 
wherein R1 is an alkyl, alkylarylakyl, alkoxyalkyl, alkylaminoalkyl or alkylamidoalkyl group, containing from about 12 to about 24 carbon atoms, branched or straight chains, saturated or unsaturated, and R2 and R3 are independently hydrogen or an aliphatic chain having from 1 to about 30 carbon atoms, and R4 is a hydrocarbyl radical having from 1 to 4 carbon atoms and a chelating agent.
The chelating agents are typically hydroxyethylaminocarboxylic acids. Preferably, the hydroxyethylaminocarboxylic acid is selected from hydroxyethylethylene-diaminetriacetic acid (HEDTA), hydroxyethyliminodiacetic acid (HEIDA), or a mixture thereof or analogous materials hydroxyalkyl, allyl or aryl-aminocarboxylic acids. Hydroxyethylaminocarboxylic acids are used essentially to remove drilling fluids deposits from the wellbore, in particular to remove filter cake. They are also used to prevent precipitation of iron species and in the removal of carbonate and sulfate scales. Ethylenediaminetetra-acetate (EDTA) is not preferred, as such a chelating agent tends to reduce the propensity for a viscous gel formation with said zwitterionic surfactants or produce a gel whose viscosity reduces with time.
At room temperature, the hydroxyethylaminocarboxylic acids may be used in presence of SDBS to improve the compatibility of the viscoelastic surfactant with the brine. However, at higher temperature such as typically encountered in a wellbore, the co-surfactant must be omitted if the brine phase comprises hydroxyethylaminocarboxylic acids, otherwise the gel is destroyed.
The carrier fluid is a brine, i.e. water comprising an inorganic salt or organic salt. Preferred inorganic monovalent salts include alkali metal halides, more preferably sodium, potassium or caesium bromide. Sodium bromide is especially preferred. The carrier brine phase may also comprise an organic salt more preferably sodium or potassium formate. Preferred inorganic divalent salts include calcium halides, more preferably calcium chloride or calcium bromide. Zinc halides, especially zinc bromide, are not preferred, as it has been observed that this salt tends to reduce the viscosity of the viscoelastic-based solution. The salt is chosen for compatibility reasons i.e. where the reservoir drilling fluid used a particular brine phase and the completion/ clean up fluid brine phase is chosen to have the same brine phase. In cases where hydroxyethylaminocarboxylic acids are used for wellbore clean up, the brine would preferably consists essentially of monovalent salts since divalent salts will be chelated making less of the hydroxyethylaminocarboxylic acid available for clean up.
The concentration of the salts in the fluid is at least high enough to bring the density of the carrier fluid to at least about 10 ppg, and preferably from about 10 ppg to about 15 ppg. Inorganic salt can be added to the carrier fluid in any hydration state (i.e. anhydrous, monohydrated, dihydrated, etc.). Organic salts such as formates may be added to the formulation up to approximately 9.5 ppg above which phase separation might occur; and consequently, some inorganic salts need to be further added to reach a density higher than 10 ppg. The tolerance of the zwitterionic surfactant to electrolyte also allows formulations below 10 ppg where the brine phase is chosen to be compatible with the brine phase of other completion or reservoir drilling fluids e.g. HCOOK or HCOONa at ca. 24 wt % (9.5 ppg) or below).
The viscoelastic zwitterionic surfactant is capable of forming structures such are micelles, that are sheet-like, spherical, vesicular, or worm-like, this latter form being preferred. A most preferred zwitterionic surfactant comprises a betaine moiety and an oleic acid moiety, such as the surfactant in BET-O-30 (Rhodia). It should be noted that the oleic acid stock from which the oleic acid moiety is derived is generally about 75% pure to about 85% pure, and the balance of the stock comprises other fatty acids, such as linolic acid, linoleic acid, etc. Some of these other fatty acids may be present in about 15% to about 25% of the molecules of the surfactant in place of the oleic acid.
The concentration of the viscoelastic surfactant in the solution is preferably between about 1 wt % and about 10 wt %. More preferably, the concentration is about 2.9 wt % to about 5 wt %.
Other components can be included in the fluid, such as scale and corrosion inhibitors or biocides, depending on its intended use, formation conditions and other parameters readily apparent to one of ordinary skill in the art. For example, as a drilling fluid, it preferably further comprises surface active agents, other viscosifiers such as polymers, filtration control agents such as Gilsonite and modified starches, density increasing agents such as powdered barites or hematite or calcium carbonate, or other wellbore fluid additives known to those skilled in the art.
As a gravel packing fluid, it preferably comprises gravel and other optional additives such as filter cake clean up reagents such as chelating agents referred to above or acids (e.g. hydrochloric, hydrofluoric, formic, acetic, citric acid) corrosion inhibitors, scale inhibitors, biocides, leak-off control agents, among others. For this application, suitable gravel or sand is typically having a mesh size between 8 and 70 U.S. Standard Sieve Series mesh.
When used as a fracturing fluid, it preferably comprises a proppant. Suitable proppants include, but are not limited to, sand, bauxite, glass beads, and ceramic beads. If sand is used, it will typically be from about 20 to about 100 U.S. Standard Mesh in size. Mixtures of suitable proppants can be used. It can also comprise a proppant flowback inhibitor, for instance the proppant can be coated with a resin to allow consolidation of the proppant particles into a mass. The concentration of proppant in the fracturing fluid can be any concentration known in the art, and will typically be in the range of about 0.5 to about 20 pounds of proppant added per gallon of clean fluid.
Another aspect of the present invention is a method of treating a wellbore including the step of injecting a high density brine carrier fluid comprising a viscoelastic zwitterionic surfactant and a co-agent such as SDBS or a chelating agent. By xe2x80x9ctreatmentxe2x80x99, it is hereby understood for instance drilling, hydraulic fracturing and gravel pack placement. As to drilling, the viscoelastic fluid is injected into the wellbore at a flow rate and pressure sufficient to lubricate the drilling bit and carry cuttings to the surface. For hydraulic fracturing, the method includes the step of injecting a viscoelastic-based fluid composition via a wellbore into a subterranean formation at a flow rate and pressure sufficient to produce or extend a fracture in the formation. For placing a gravel pack, the method includes the step of injecting the viscoelastic-based fluid composition comprising gravel into a wellbore at a flow rate and pressure sufficient to emplace a gravel pack in the wellbore. Preferably, the method is performed in formations having a temperature less than about 260xc2x0 F. (126.7xc2x0 C.) and preferably using alternate path technology known for instance from U.S. Pat. No. 4,945,991.
Regardless of the intended use, the fluid can be prepared at any time prior to use by combining the viscoelastic surfactant, the co-surfactant and or the chelating agent, and the high density brine carrier fluid, as well as any further components. The viscoelastic surfactant typically can be provided in an aqueous solution, but also can be provided in any other form. The high density brine carrier fluid can be prepared by the addition of the inorganic salt to the carrier fluid any time before, during, or after addition of the viscoelastic surfactant to the fluid. Additives to be included in the fluid can be added to the fluid at any time prior to use or even added to the fluid after it has been injected into the wellbore.
The compositions and methods of the present invention provide several substantial advantages over prior fluids and methods. Though not to be bound by theory, it is believed that the co-agent/co-surfactant functions to allow the VES to substantially retain its viscosity in the presence of high inorganic or organic salt concentrations. The fluids retain sufficient viscosity without SDBS co-surfactant if the fluid formulation also comprises some chelating agents such as HEDTA or HEIDA. The present invention also is relatively simple and inexpensive to manufacture.